This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Field of the Invention
The present disclosure relates to the field of hydrocarbon recovery operations. More specifically, the present invention relates to hydraulically actuated pumping units for the production of hydrocarbon fluids and for dewatering gas wells.
Technology in the Field of the Invention
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the surrounding formations.
To prepare the wellbore for the production of hydrocarbon fluids, a string of tubing is run into the casing. A packer is set at a lower end of the tubing to seal an annular area formed between the tubing and the surrounding strings of casing. The tubing then becomes a string of production pipe through which hydrocarbon fluids may be lifted.
In order to carry the hydrocarbon fluids to the surface, a pump may be placed at a lower end of the production tubing. This is known as “artificial lift.” In some cases, the pump may be an electrical submersible pump, or ESP. ESP's utilize a hermetically sealed motor that drives a multi-stage pump. More conventionally, oil wells undergoing artificial lift use a downhole reciprocating plunger-type of pump. The reciprocating downhole pump is relatively long and thin to avoid restricting oil flow up the well. The pump has one or more valves that capture fluid on a down stroke, and then lift the fluid on the upstroke. This is known as “positive displacement.” In some designs such as that disclosed in U.S. Pat. No. 7,445,435, the pump may be able to both capture fluid and lift fluid on each of the down stroke and the upstroke.
Conventional positive displacement pumps have a barrel that is reciprocated at the end of a “rod string.” The rod string comprises a series of long, thin joints of pipe that are threadedly connected through couplings. The rod string is pivotally attached to a pumping unit at the surface. The rod string moves up and down within the production tubing to incrementally lift production fluids from subsurface intervals to the surface.
Most pumping units on land are so-called rocking beam drive units. Rocking beam units typically employ electric motors or internal combustion engines having a rotating drive shaft. The shaft turns a crank arm, or possibly a pair of crank arms. The crank arms, in turn, have heavy, counter-weighted flywheels. The flywheels rotate along with the crank arms. Rocking beam units also have a walking beam. The walking beam pivots over a fulcrum. One end of the walking beam is mechanically connected to the crank arms. As the crank arms and flywheels rotate, they cause the walking beam to reciprocate up and down over the fulcrum.
The opposite end of the walking beam is a so-called horse head. The horse head is positioned over the well head at the surface. As the walking beam is reciprocated, the horse head cycles up and down over the wellbore. This, in turn, translates the rod and attached pump up and down within the wellbore. A drawing and further description of a walking beam unit are provided in U.S. Pat. No. 7,500,390, which is incorporated herein in its entirety by reference.
Another type of pumping unit is a hydraulic actuator system. These systems employ a cylinder residing over a wellbore. The cylinder is axially aligned with the wellbore and holds a reciprocating piston. The cylinder cyclically receives fluid pressure through an oil line. As fluid is injected through the oil line and into the cylinder, the piston is caused to move linearly within the cylinder. This, in turn raises the connected rod string, causing the pump to undergo an upstroke. When fluid pressure is released from the cylinder, the rod string is lowered due to gravitational forces, causing the downhole pump to undergo a downstroke.
Surface hydraulic actuator systems have been used successfully for many years. Such systems offer a beneficially long stroke length for the downhole plunger pump. Such systems are also ideal for urban environments where a small footprint is demanded. Further, such systems offer the ability to operate more than one well from a single surface installation.
During operation of any rod pump system for a producing well, it is desirable to be able to monitor the position of the rod string and specifically, the piston within the cylinder. In this respect, it is helpful to know when the piston is about to reach a top or bottom of a stroke. Knowing this position allows the operator to slow or stop the motion of the piston and rod-string pro-actively, eliminating the “slamming” of the piston against a plate within the cylinder.
Further, it is desirable to be able to measure the load on the sucker rods making up the rod string. The load can be recorded and printed out on a so-called surface dynamometer card. The “dyno card” offers a plot of the measured rod loads at various positions throughout a complete stroke. The load is usually displayed in pounds of force, while the position is usually displayed in inches. The pump dynamometer card represents the load the pump applies to the bottom of the rod string. Dynamometer cards are displayed by predictive and diagnostic software for the purposes of design and diagnosing sucker rod pumping systems.
Historically, hydraulic pressure has been used to measure rod loads for dynamometer cards. Then, separate physical measurements have been made on the piston and polished rod for determining position. This requires the use of sensors at the wellhead to directly measure piston position. Such sensors may be either discrete position switches or more advanced linear position sensors. SPE Paper No. 113186 entitled “Optimizing Downhole Fluid Production of Sucker-Rod Pumps With Variable Speed Motor” (2009) describes some of the mathematics behind the dynagraph calculations, and is incorporated herein by reference in its entirety.
A need exists to be able to use the hydraulic fluid data to determine not only the load on the rod string, but also the position of the piston using only the hydraulic fluid as the measurement for both position and load without the need for data gathered from devices or sensors at or near the wellhead. Removal of electronic or other methods of directly attached instrumentation from areas around the wellhead reduces risk of sparking and also eliminates the cost of placing and maintaining such instrumentation. Further, it is desirable to be able to determine the position of the piston within the cylinder on both the upstroke and the down stroke at a safe distance without using position sensors at the wellhead.